Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 01 August 2020. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening.
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The EIA reported 1,418,000 more barrels of oil production per day in May than was actually produced; natural gas prices rose by most in any week since 2009; distillates supplies at a third straight 38 year high; oil rig count now lowest in 15 years.
Oil prices finished higher this week on falling US oil inventories, after first jumping when a fertilizer explosion wiped out the Lebanese port of Beruit…after falling 2.5% to $40.27 a barrel last week after the GDP report showed that the US economy had shrunk at a 32.9% rate in the second quarter, the contract price of US light sweet crude for September delivery fell early on Monday on oversupply concerns as OPEC and its allies rolled back their production cuts to begin August and a rise in worldwide COVID-19 cases pointed to a slower pick-up in fuel demand, but turned higher after reports indicated a pickup of manufacturing in the US and Europe in July and finished the session with a gain of 74 cents at $41.01 a barrel after an explosion at the port of Beirut stoked fears of instability in the region…oil prices rose another 69 cents to $41.70 a barrel on Tuesday on hopes that Congress would pass a new economic stimulus package and on signs that the US is making progress on curbing the coronavirus spread, as a tumbling US dollar swept commodity prices higher across the board…oil prices then rose to their highest since early March on Wednesday after U.S. crude inventories fell sharply and the dollar weakened further, with US crude pushing to as high as $43.52 a barrel before backing off and closing just 49 cents higher at $42.19 a barrel, as mounting coronavirus infections kept traders worried about the demand outlook…oil prices then turned lower on Thursday on concerns that fuel demand remained depressed by the economic slowdown due to the coronavirus pandemic and finished down 24 cents at $41.95 a barrel as “everyone was waiting for the coronavirus relief package to come through to give a bounce to the economy,”…oil prices then fell another 73 cents to $41.22 on Friday despite a stronger than expected US jobs report as US-China tenstions mounted after Trump imposed a sweeping ban on the popular Chinese consumer apps Tik Tok and WeChat and concerns persisted about the impact of the coronavirus on demand, but still finished the week 2.4% higher as traders remained upbeat in the face of a reduction in output cuts by major producers that took effect on August 1st.
Natural gas prices rose by the most in any week since 2009 this week as the weather forecast turned hotter and prices in Europe rose, increasing demand for US exports…after falling 5.0% to $1.799 per mmBTU last week on forecasts for cooler weather and the end of a tropical storm threat, the contract price of natural gas for August delivery jumped 30.2 cents or nearly 17% to a near three-month high of $2.101 per mmBTU on Monday, as demand for exports of liquefied natural gas (LNG) rose, and as weather forecasters called for a return to hot weather and increased cooling demand next week….prices continued higher on Tuesday, rising 9.2 cents to $2.193 per mmBTU, the highest front month price since January, on forecasts for hot weather through late August after Hurricane Isaias passed, keeping East Coast demand for air conditioning high…the rally stalled on Wednesday as natural gas prices slipped two-tenths of a cent, and prices then fell another 2.4 cents on Thursday after a larger-than-expected storage injection sapped the price momentum and reminded traders that US gas is still solidly oversupplied….but the rally in gas resumed Friday, as prices rose 7.3 cents, or 3.4%, to settle at $2.238 per mmBTU, as LNG exports increased again and forecasts continued calling for hot weather through late August, with prices thus finishing the week 24% higher at their highest close since Dec. 26th..
The natural gas storage report from the EIA for the week ending July 31st indicated that the quantity of natural gas held in underground storage in the US rose by 33 billion cubic feet to 3,274 billion cubic feet by the end of the week, which left our gas supplies 601 billion cubic feet, or 22.5% greater than the 2,673 billion cubic feet that were in storage on July 31st of last year, and 429 billion cubic feet, or 15.1% above the five-year average of 2,845 billion cubic feet of natural gas that have been in storage as of the 31st of July in recent years….the 33 billion cubic feet that were added to US natural gas storage this week was more than the average 27 billion cubic feet increase that was forecast by analysts polled by S&P Global Platts, but it was much less than the 58 billion cubic feet addition of natural gas to storage during the corresponding week of 2019, while it matched the average of 33 billion cubic feet of natural gas that has been added to natural gas storage during the same week over the past 5 years..
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending July 31st showed that even with a jump in our oil imports and a modest decrease in our oil exports, we still needed to withdraw oil from our stored supplies for the 4th time in the past nine weeks…our imports of crude oil rose by an average of 864,000 barrels per day to an average of 6.010,000 barrels per day, after falling by an average of 794,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 392,000 barrels per day to an average of 2,819,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3.191,000 barrels of per day during the week ending July 31st, 1,256,000 more barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was reportedly 100,000 barrels per day lower at 11,000,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 14,191,000 barrels per day during this reporting week..
US oil refineries reported they were processing 14,637,000 barrels of crude per day during the week ending July 31st, 42,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that a net of 1,054,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 609,000 barrels per day more than what our oil refineries reported they used during the week..to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (-609,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the data for the average daily consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting an error or errors of that magnitude in the oil supply & demand figures we have just transcribed….(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 5,666,000 barrels per day last week, which was 18.1% less than the 6,918,000 barrel per day average that we were importing over the same four-week period last year….the 1,054,000 barrel per day net withdrawal from our total crude inventories came as 1,053,000 barrels per day were being pulled out of our commercially available stocks of crude oil and 1,000 barrels per day were being withdrawn from the oil supplies in our Strategic Petroleum Reserve….this week’s crude oil production was reported to be 100,000 barrels per day lower at 11,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states fell by 100,000 barrels per day to 10,600,000 barrels per day, while a 16,000 barrel per day decrease in Alaska’s oil production to 432,000 barrels per day was not enough to impact the rounded national total….last year’s US crude oil production for the week ending August 2nd was rounded to 12,300,000 barrels per day, so this reporting week’s rounded oil production figure was about 10.6% below that of a year ago, yet still 30.5% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…
We have often cautioned that the weekly oil production figures we report on are preliminary, and that the final revised oil production figures for the current week will not be released until more than two months later…Friday of last week saw the release of just such a final figure for May’s oil output, and it indicates that’s the EIA had massively overestimated US oil production in their weekly reports during that month….to show you how bad the EIA’s estimates were, we’ll start by showing you a section of the weekly spreadsheet for US oil production, which is not corrected when the revised figures come out, and hence continues to show oil production as originally reported:
The above table excerpt was copied from the EIA’s html spreadsheet for the Weekly U.S. Field Production of Crude Oil, which shows their weekly estimates of US crude oil output in thousands of barrels per day going back to 1983….to facilitate pointing out the figures we’re talking about, we have highlighted the weekly May figures in a red box, although we’d also note that output for the last two days of May is included in the first figure on the June line…the figures we report weekly are taken from this table, and show that the EIA had reported oil output at 11,900,000 barrels per day during the week ending May 1st, 11,600,000 barrels per day during the week ending May 8th, 11,500,000 barrels per day during the week ending May 15th, 11,400,000 barrels per day during the week ending May 22nd and 11,200,000 barrels per day during the week ending May 29th…including production at 11,100,000 barrels per day for May 30th and 31st, that means that the EIA had reported average production of 11,419,000 barrels per day during the month of May…
Now we’ll include a section of the table showing confirmed monthly oil production, which was just updated with the May figures last Friday…
This table was copied from the EIA’s html spreadsheet for U.S. Field Production of Crude Oil, and it shows the confirmed production figures for US crude oil in thousands of barrels per day going back to 1920…circled in red, we have the final confirmed oil production figure for May, showing that US oil production in May was actually 10,001,000 barrels per day during the month…that means the EIA’s weekly reports for oil production in May averaged 1,418,000 barrels per day above what was actually produced…it’s now obvious that US oil producers throttled back oil production after pricing for May oil briefly slipped below $0, but that the EIAs weekly estimates failed to capture that…it’s also obvious that this accounts for those large “unaccounted for crude oil” figures we had been noting on line 13 of the weekly U.S. Petroleum Balance Sheet during this period, errors the EIA dismissed at the time by saying their averages were only off by around 1%…
Returning to this week’s report, US oil refineries were operating at 79.6% of their capacity while using 14,637,000 barrels of crude per day during the week ending July 31st, up from 79.5% of capacity during the prior week, but excluding the 2005, 2008, and 2017 hurricane-related refinery interruptions, still one of the lowest refinery utilization rates of the last thirty years…hence, the 14,637,000 barrels per day of oil that were refined this week were still 17.7% fewer barrels than the 17,777,000 barrels of crude that were being processed daily during the week ending August 2nd, 2019, when US refineries were operating at 95.1% of capacity….
With the increase in the amount of oil being refined, gasoline output from our refineries was also higher, increasing by 142,000 barrels per day to 9,300,000 barrels per day during the week ending July 31st, after our refineries’ gasoline output had increased by 79,000 barrels per day over the prior week… but with our gasoline production still recovering from a multi-year low, this week’s gasoline output was still 10.8% less than the 10,421,000 barrels of gasoline that were being produced daily over the same week of last year….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 126,000 barrels per day to 4,909,000 barrels per day, after our distillates output had decreased by 20,000 barrels per day over the prior week… after this week’s increase in distillates output, our distillates’ production was 7.1% less than the 5,286,000 barrels of distillates per day that were being produced during the week ending August 2nd, 2019….
Along with with the increase in our gasoline production, our supply of gasoline in storage at the end of the week increased for the 2nd time in 5 weeks and for the 9th time in 27 weeks, rising by 419,000 barrels to 247,806,000 barrels during the week ending July 31st, after our gasoline supplies had increased by 654,000 barrels over the prior week…our gasoline supplies increased this week because the amount of gasoline supplied to US markets decreased by 192,000 barrels per day to 8,617,000 barrels per day, even as our imports of gasoline fell by 267,000 barrels per day to 657,000 barrels per day and as our exports of gasoline rose by 329,000 barrels per day to 770,000 barrels per day….after this week’s inventory increase, our gasoline supplies were 5.4% higher than last August 2nd’s gasoline inventories of 235,172,000 barrels, and roughly 8% above the five year average of our gasoline supplies for this time of the year…
Similarly, with the increase in our distillates production, our supplies of distillate fuels increased for the fifteenth time in 29 weeks and for the 20th time in 44 weeks, rising by 1,591,000 barrels to another 38 year high of 179,977,000 barrels during the week ending July 31st, after our distillates supplies had increased by 503,000 barrels over the prior week….our distillates supplies rose again this week even though the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 65,000 barrels per day to 3,700,000 barrels per day, because our exports of distillates fell by 111,000 barrels per day to 1,113,000 barrels per day while our imports of distillates fell by 17,000 barrels per day to 131,000 barrels per day…after this week’s inventory increase, our distillate supplies at the end of the week were 30.9% above the 137,451,000 barrels of distillates that we had in storage on August 2nd, 2019, and about 27% above the five year average of distillates stocks for this time of the year…
Finally, with the jump in our oil imports and the decrease in our oil exports, our commercial supplies of crude oil in storage fell for the 7th time in twenty-nine weeks and for the 15th time in the past year, decreasing by 7,373,000 barrels, from 525,969,000 barrels on July 24th to 518,596,000 barrels on July 31st…but even after that decrease, our our commercial crude oil inventories were still around 16% above the five-year average of crude oil supplies for this time of year, and around 54% above the prior 5 year (2010 – 2014) average of our crude oil stocks for the fourth weekend of July, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels….since our crude oil inventories have generally been rising since September of 2018, except for during last summer, after generally falling until then through most of the prior year and a half, our crude oil supplies as of July 31st were 18.2% above the 438,930,000 barrels of oil we had in commercial storage on August 2nd of 2019, 27.3% more than the 407,389,000 barrels of oil that we had in storage on August 3rd of 2018, and 9.1% above the 475,437,000 barrels of oil we had in commercial storage on August 4th of 2017…
This Week’s Rig Count
After being unchanged during the week ending July 31st, the US rig count was down for the 21st time in 22 weeks during the week ending August 7th, and is now down by 68.9% over that twenty-two week period….Baker Hughes reported that the total count of rotary rigs running in the US fell by 4 rigs to 247 rigs this past week, which was the fewest active rigs in Baker Hughes records going back to 1940 and 157 fewer rigs than the all time low prior to this year…it was also down by 687 rigs from the 934 rigs that were in use as of the August 9th report of 2019, and 1,682 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business….
The number of rigs drilling for oil decreased by 4 rigs to 176 oil rigs this week, after decreasing by 1 oil rig the prior week, leading to the lowest oil rig count since July 15th, 2005… that was also 588 fewer oil rigs than were running a year ago, and less than a ninth of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations was unchanged at 69 natural gas rigs, which was still down by 100 natural gas rigs from the 169 natural gas rigs that were drilling a year ago, and was also less than a twentieth of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to those rigs drilling for oil & gas, two rigs classified as ‘miscellaneous’ continued to drill this week; one on the big island of Hawaii, and one in Sonoma County, California… a year ago, there was just one such “miscellaneous” rig deployed…
The Gulf of Mexico rig count was unchanged at 12 rigs this week, with 9 of those rigs drilling for oil in Louisiana’s offshore waters and three drilling for oil offshore from Texas…that was 11 fewer rigs than the 23 rigs drilling in the Gulf a year ago, when all 23 Gulf rigs were drilling offshore from Louisiana…while there are no rigs operating off other US shores at this time, a year ago there were also two rigs deployed offshore from Alaska, so this week’s national offshore count is down by 13 from the national offshore rig count of 25 a year ago
The count of active horizontal drilling rigs was down by 5 to 211 horizontal rigs this week, which was the least horizontal rigs deployed since November 18, 2005, and also 606 fewer horizontal rigs than the 817 horizontal rigs that were in use in the US on August 9th of last year, and less than a sixth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014…at the same time, the vertical rig count was down by one to 12 vertical rigs this week, and those were also down by 40 from the 52 vertical rigs that were operating during the same week of last year….on the other hand, the directional rig count was up by 2 to 24 directional rigs this week, but those were still down by 41 from the 65 directional rigs that were in use on August 9th of 2019….
The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of August 7th, the second column shows the change in the number of working rigs between last week’s count (July 31st) and this week’s (August 7th) count, the third column shows last week’s July 31st active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 9th of August, 2019…
As you can see, there were only a few changes in drilling activity this week, with just a handful of rig removals and just a couple rig additions, which suggests that prices are currently high enough that drillers are no longer hurrying to shut down money-losing operations, but not high enough to encourage the addition of new rigs to the field…checking the rig counts in the Texas part of Permian basin, we find that one rig was shut down in Texas Oil District 7C, which corresponds to the southern Permian Midland, while rigs were added in both Texas Oil District 8, which is the core Permain Delaware, and Texas Oil District 8A, or the northern Permian Midland….since the Texas Permian count has thus increased by 1 while the national Permian basin rig count was down by 2 rigs, that strongly suggests that all 3 rigs that were removed from New Mexico would have been drilling in the western Permian Delaware up until this week, to account for the national decrease…elsewhere in Texas, there was also an oil rig removed from Texas Oil District 1, which would correspond to the one rig decrease in the Eagle Ford shale that we see above…that still appears to leave us with one oil rig removal unaccounted for, but what we had overlooked is that of the 2 rig start-ups in the Texas Permian, one was drilling for natural gas – the first Permain basin natural gas rig deployment this year…that Permian gas rig startup thus masked the simultaneous shut down of an additional Permian basin oil rig, resulting in our 4 rig decrease nationally…meanwhile, the national natural gas rig count still remained unchanged because a natural gas rig was shut down in a Mississippi basin not tracked separately by Baker Hughes, which thus doesn’t appear here…that shut down left no rigs remaining in Mississippi, which was down from the six rigs that were deployed in the state a year ago…
Resident wants to inform others of fracking issues – The Columbus Dispatch — Residents of Southeastern Ohio need to be aware of a recent announcement made by Pennsylvania Attorney General Josh Shapiro on the hazards of the oil and gas industry. He reported that a two-year investigation by the Grand Jury uncovered the failure to protect Pennsylvanians from the inherent risks of the fracking industry. Testimonies were given to the jury from residents living near oil and gas drilling sites. They shared their concerns over poor air quality leading to negative health impacts. Reports were given of water contamination which resulted in breathing problems when showering. Parents spoke about their children having nose bleeds and other ailments. Livestock had become sick, infertile and died, according to testimony given by farmers living near fracking operations.Pennsylvania has more stringent regulations of the oil and gas industry than Ohio. In fact, 1,500 fracking wells had been drilled in Ohio before a single regulation had even been written. Ohio is still lacking in the necessary oversight of the fracking industry, with critical legislation yet to be written. As an informed and concerned resident of Belmont County, I am pleading with fellow Ohioans to stand with me and demand that Ohio Attorney General David Yost and Governor Mike DeWine halt any further permitting for the oil and gas industry until a public health and environmental impact study is conducted in Ohio on the risks of fracking. Just as in Pennsylvania, the State of Ohio is already failing to protect communities from air and water pollution from fracking, and now the Ohio EPA has granted permits for, and is promoting cracking to make plastic, which will pose additional threats to our health due to air and water pollution. Belmont County is the most heavily fracked county in the state, with over 675 wells permitted and 500 producing. Alarmingly, 78 of those wells are located within a five-mile radius of my home. There are four well sites, one within a mile and the remaining three within a mile and a half, that have been in significant violation since 2016. Investigations revealed that no enforcement action had been taken by the Ohio Environmental Protection Agency (OEPA), or remediation of any kind been made by Gulfport, the fracking company in violation. There are a total of 16 Gulfport well pads in our area that have been in violation since 2016. My family and my neighbors have experienced negative health impacts from fracking wells and other infrastructure sites located nearby including, pipelines, compressor and transfer stations.
BARGING Oil and Gas WASTE on the OHIO RIVER is Too Much RISK – A new threat recently emerged for communities along the Ohio River.Three barge docks are proposed to be built along the riverto transport oil and gas waste from horizontal and vertical fracking operations. The projects, if approved, could result in the first barges carrying briny fracking wastes on the Ohio River.The terminals would be developed by 4K Industrial Frac Water Supply and Recycling Technologies in Martins Ferry, DeepRock Disposal Solutions about 61 miles downstream at Marietta, and by Fountain Quail Energy Services about 38 miles downstream from Marietta in Meigs County, Ohio.According to Dr. Randi Pokladnik, a retired research chemist and volunteer with the Ohio Valley Environmental Coalition (OVEC), these operations pose a substantial risk for the Ohio River – the primarily tap water source for approximately five million people.”Citizens have every right to be concerned about yet another threat to their drinking water,” says Dr. Pokladnik. “A quick glance of the Environmental Working Group’s (EWG) data collected from public drinking water suppliers along the Ohio River reveals that all public drinking water sources along the river have pollutants that in many cases exceed the EWG health standards and in some cases exceed federal standards.“Based on current regulations, it is unclear what agencies would be tasked with responding to potential spills as a result of these new barging operations, and whether or not those agencies would be able to work together successfully to address the environmental and public health hazards associated with these pollutants.Even worse, many public water treatment facilities are not equipped to filter out the contaminants if this conventional and unconventional oil and gas waste is spilled in the Ohio River. For example, some contaminants, such as radioactive chemicals in water, can only be removed using very specific techniques that are not currently utilized by most public water treatment facilities in our region.In response to requests and comments from concerned citizens, the U.S. Army Corps of Engineers has scheduled a virtual public hearing on Friday, August 7, for the DeepRock barge dock near Marietta, Ohio.
Utica Shale well activity as of Aug. 1 – Six horizontal permits were issued during the week that ended Aug. 1, and 6 rigs were operating in the Utica Shale.
- DRILLED: 157 (151 as of July 18)
- DRILLING: 99 (100)
- PERMITTED: 507 (498)
- PRODUCING: 2,523 (2,523)
- TOTAL: 3,286 (3,272)
TOP COUNTIES BY NUMBER OF PERMITS:
- 1. BELMONT: 697 (691 as of July 18)
- 3. HARRISON: 532 (524)
- 2. CARROLL: 530 (530)
- 4. MONROE: 438 (438)
Gulfport updates Utica Shale plans – Gulfport Energy continues to drill Utica Shale wells as the company positions its natural gas production to peak during the colder months. The Oklahoma City-based company previously announced it would curtail production until later this year and early 2021, with the hope that natural gas prices, which are at 25-year lows, would eventually rise. Gulfport plans to complete seven more Utica wells during the second half of this year, and the company said it would run one drilling rig in the Utica through the third quarter. The company has drilled more than 400 wells in Ohio’s Utica Shale, the most of any publicly traded company. “While there is little low-hanging fruit remaining, the team continues to gain efficiencies through the drill bit and deliver on expectations quarter after quarter,” Gulfport President and CEO David Wood said during a presentation Wednesday. The company said it still expects annual production to fall between 1 billion and 1.075 billion cubic feet equivalent per day.During the second quarter, Gulfport’s production averaged 1.03 billion cubic feet equivalent per day, comprising 91 percent natural gas, 6 percent natural gas liquids and 3 percent oil.Three-quarters of the production was in the Utica Shale, where Gulfport drilled five wells and made 10 wells ready for production during the quarter. Gulfport lost $561.1 million, or $3.51 per diluted share, during the second quarter.
Gulfport Keeping Utica Natural Gas Curtailed to Await Better Prices – Gulfport Energy Corp. is still curtailing Appalachian natural gas production in anticipation of better prices later this year and into 2021. Given an uncertain economic outlook, weak energy demand and a slight rebound in associated gas volumes, Gulfport remains “cautious near-term on natural gas pricing,” said CEO David Wood during a call to discuss second quarter results. The company made the decision during the second quarter to shut-in some Utica Shale gas production along with vertical oil wells in the South Central Oklahoma Oil Province (SCOOP) because of low liquids prices. Nearly all of the SCOOP wells have returned to production. “Based on current natural gas pricing, we plan to continue executing on our curtailment strategy, shaping our production profile to peak in the colder months of the year,” Wood said of the Utica curtailments. “This is in line with our updated guidance provided in June.” The independent also plans to complete another seven gross Utica wells in the second half of the year, up from a plan announced in June to complete three. Through the first six months of the year, 13 net operated wells had been completed in the Utica with 3.8 net operated wells in the SCOOP. “This additional activity provides incremental production late this year and into early 2021 in the anticipation of higher prices during the winter months,” management said. The company reaffirmed its 2020 full-year net production at 1.0-1.075 Bcfe/d. Management also said drilling and completion efficiencies would likely help spending come in at the low end of its previously announced $285-310 million capital expenditure budget. Gulfport reported a decline in average realized prices during the second quarter, including transportation costs and cash-settled derivatives, of $2.46/MMcfe, compared with $2.52 in the year-ago period. Revenue also fell year/year to $132.4 million from $459 million.
Ohio State students, faculty testify for, against on-campus natural gas plant – OSU – The Lantern -Several members of the Ohio State community testified at a virtual public hearing Tuesday night to discuss the university’s proposed $278 million plan to construct a combined heat and power plant on campus, made possible by the university’s partnership with energy companies.The forum – the second public hearing hosted this summer by the Ohio Power Siting Board – included testimonies from nearly 50 individuals, the majority of whom cited the detrimental health and climate risks of the proposal. Others advocated for the adoption of the proposal, referencing potential job growth and a reported decline in carbon emissions if the plant is constructed.According to Ohio State’s proposal application, the combined heat and power plant will produce thermal energy powered by natural gas, requiring the use of fracking, a process of drilling into the earth to extract natural gas, raising many environmental concerns from members of the Ohio State community.Ohio State first submitted an initial application for the construction of the plant to the Ohio Power Siting Board November 2019, and the Sierra Club, an environmental advocacy organization, submitted a petition to intervene in the case in March 2020. The proposed facility would include a main building standing 60 feet tall, cooling towers extending 27 feet off the roof and two 125-foot steel stacks, according to the Ohio Power Siting Board website. The plant would be located on a 1.18 acre parcel of university-owned land on West Campus and serve as the main source of electricity and heating for the Columbus campus.
Pennsylvania Regulators Won’t Say Where 66% of Landfill Leachate w/ Radioactive Material From Fracking is Going…”It’s Private” – Janice Blanock talks to Public Herald about losing her son Luke Blanock to Ewing Sarcoma in 2016. PA DEP’s TENORM data could play a critical role in helping the Blanock’s discover whether oil and gas had anything to do with what happened to Luke. Nina Berman for Public Herald (podcast & story) In Pennsylvania, the final destination of 66 percent of liquid waste from 30 municipal landfills accepting fracking’s oil and gas waste remains unknown. Oil and gas waste from fracking contains high concentrations of Technically Enhanced Naturally Occurring Radioactive Materials (TENORM), and wherever this radioactive TENORM waste is stored, rain carries water-soluble radionuclides such as Radium-226 through the landfill to create what’s known as leachate – the landfill’s liquid waste. This TENORM-laden leachate is commonly sent to Waste Water Treatment Plants (WWTPs) that are not equipped to remove it before it’s dumped into rivers.If you’re talking about fracking, you’re talking about TENORM, which is present throughout the process in waste streams like pipe scale, sludge, drill cuttings, wastewater, and contaminated equipment. What starts as Naturally Occurring Radioactive Material (NORM) contained deep beneath the Earth’s surface is brought to the surface by fracking and concentrated into TENORM.Public Herald has made several attempts with the Pennsylvania Department of Environmental Protection (DEP) to verify the destination of landfill leachate containing TENORM, but DEP stopped responding to our inquiries after we published the August 2019 statewide report on how fracking’s radioactive waste enters public waters. Our team has since been forced to rely on delayed Right-to-Know Law requests and DEP’s limited online data.From the limited data DEP provided to Public Herald in 2019, and from what our team in 2020 has discovered, we now know and mapped the whereabouts of 34 percent of leachate from a limited number of landfills accepting fracking’s oil and gas waste in Pennsylvania.
Shell completes Appalachia shale gas exit – Royal Dutch Shell has completed the sale of its U.S. Appalachia assets to National Fuel, exiting its shale gas position in the Marcellus and Utica plays. The $541 million cash transaction was completed on July 31 and has an effective date of January 1, 2020. The assets were sold to Seneca Resources Company and NFG Midstream Covington – both subsidiaries of National Gas Fuel Gas Company (NFG). The Appalachian assets, located mostly in northern and western Pennsylvania, include 350 active wells in the Marcellus and Utica shale plays. Together, they produce roughly 250 million cubic feet per day of dry gas, Kallanish Energy notes. Shell’s Upstream director Wael Sawan had previously said the divestment in Appalachia was consistent with the company’s “desire to focus our Shales portfolio.” Shell said it continues to have “attractive opportunities” in its unconventional portfolio inside and outside the U.S., focusing on driving down costs while increasing efficiency. The deal also included the transfer of Shell owned and operated midstream infrastructure, but doesn’t impact Shell’s commitment to Pennsylvania and its planned petchem complex.
Cost Of Shale Gas Drilling Permit In Pennsylvania Jumps 150% – Pennsylvania more than doubled as of August 1 the fee for all unconventional well permit applications, while shale companies call on state officials to find other mechanisms to fund the oil and gas program of the Pennsylvania Department of Environmental Protection.The fee for all unconventional well permit applications is now $12,500 – up from US$5,000 for nonvertical unconventional wells and US$4,200 for vertical unconventional wells. The increase is designed “to sustain the Program at current staff levels and operating costs,” according to the new rule. However, the rule and the decision to hike the fees by 150 percent were made on the basis of well permit analyses in the period 2014 through 2017, and were outdated even before the current crisis in the oil and gas industry, Laura Legere of Pittsburg Post-Gazette writes.The state reviews the fees every three years, but Neil Shader, spokesman of the Department of Environmental Protection, told the Pittsburg Post-Gazette that “we will revisit the fee schedule accordingly.”The Department of Environmental Protection of Pennsylvania – the state home to parts of the Marcellus and Utica shale gas basins – funds a large part of its oil and gas program with the fees for well permit applications.The Marcellus Shale Coalition says that the fees for well permit applications in Pennsylvania are now the highest in the United States and called for the Department of Environmental Protection and the administration to “continue to strongly urge DEP and the administration to pursue a more sustainable and equitable funding mechanism for its oil and gas program,” as carried by Pittsburg Post-Gazette. The department has issued just 523 permits to companies in the first half this year, the lowest number of permits since 1993, as the low natural gas prices and the pandemic-driven demand crash discouraged firms from rushing to secure well permits.Gas production in the Appalachia shale basin is expected to drop by 210 million cubic feet/day between July and August, to 32.713 billion cubic feet/day this month, according to EIA’s latest Drilling Productivity Report.
US FERC releases favorable environmental review for PennEast Pipeline | S&P Global Platts – In a step forward for the stalled PennEast Pipeline project, staff of the Federal Energy Regulatory Commission has found the developers’ new plan to divide the project into two phases would not constitute a major federal action significantly affecting the environment. The roughly 118-mile, 1.1 Bcf/d natural gas pipeline project, originally intended to link Marcellus Shale dry gas production with markets in Pennsylvania, New Jersey and New York, has faced regulatory hurdles in New Jersey, and an appeals court ruling thwarting its ability to condemn lands in which the state held an interest. To help the project advance in spite of those obstacles, PennEast proposed to amend the authorization and begin with a first phase, a 68-mile segment in Pennsylvania with the capacity to carry 695,000 Dt/d. A second phase segment, mostly in New Jersey, would enable the full capacity. The commission’s plans to conduct an environmental assessment by July 10 focused on the limited new facilities required to build the project in two phases. It drew pushback from those calling for a more extensive review or more explanation of the need for each phase. After the July 10 target date for the EA passed, PennEast recently argued that prompt release was critical for the project to meet shippers’ needs for firm natural gas transportation service on the Phase I facilities by the winter 2012-22 hearing season. Commission staff acted Aug. 3, releasing a favorable report for the project, mostly focused on the impacts of building a new above-ground facility within a 2.1-acre site – the Church Road interconnects in Bethlehem Township, Pennsylvania. The EA also considered effects of phasing in the pipeline on three areas, air quality, socioeconomics and cumulative impacts. Tony Cox, chair of the PennEast Pipeline board of managers, welcomed the action as “another boost” for the project, which he described as “necessary to meet the vital and growing demand in the region for clean, low-cost, reliable natural gas to serve homes and businesses.” The staff environmental report, however, drew quick criticism from some that have opposed the project and FERC’s regulation of it. “This is a new low in the commission’s consideration, or lack thereof, of this project,” said Jennifer Danis, senior fellow of the Sabine Center for Climate Change Law. “FERC asserts that ‘the project’ won’t impact waters of the US because it is only about building the Church Street interconnect – while paradoxically defining project purpose as building both Phase 1 and Phase 2.” Her group and others challenging PennEast contend that FERC lacks jurisdiction to consider the proposal as a certificate amendment since the original certificate is already on appeal and jurisdiction already has shifted to the appeals court.
Cuomo signs hazardous waste bill, closing loophole allowing import of gas drilling waste from Pennsylvania – FingerLakes1.com -Gov. Andrew Cuomo signed a bill Monday that makes New York the first state in the nation to apply hazardous waste laws to potentially toxic oil and gas byproducts.The action, coming just months after the state codified into law its 2014 policy ban on fracking for shale, solidifies the governor’s legacy of applying public health standards to a powerful and often weakly regulated industry.The bill’s legislative sponsors and leading environmental groups praised the governor for closing a “dangerous loophole” in the way oil and gas wastes are regulated.However, throughout Cuomo’s near-decade in office, oil and gas drilling wastes from hundreds of fracked Pennsylvania wells have been dumped in upstate New York landfills and spread on the state’s roadways.Dr. David Carpenter, director of the Institute for Health and the Environment at the University of Albany, said in anaffidavit: “The net effect of New York accepting drill cuttings and de-watered mud from Pennsylvania fracking sites will be that New Yorkers will have an increased risk of cancer, especially lung and gastrointestinal cancers, and increase of birth defects coming from DNA damage and an increased risk of shortened life span.”Anthony Ingraffea, a retired professor of rock mechanics at Cornell University, said in a recent interview: “Perhaps we’ll never know what the environmental and health impacts of all that (fracking waste) currently in New York will be. They’ve made our bed, and now we have to lie in it.”Since January 2011, New York landfills have imported more than 638 thousand tons of waste from Marcellus shale gas wells in Pennsylvania, according to records that state maintains. (New York doesn’t maintain its own statistics). Those landfills and unrelated transfer stations have imported more than four thousand barrels of liquid shale drilling wastes. (A graphic below by Melissa Troutman of Earthworks uses Pennsylvania data to show NY imports of Pennsylvania’s shale waste from 2011 to 2019.)
Cuomo bans hydrofracking waste from coming to New York – In what environmentalists are hailing as the closing of a loophole and a blow to the hydrofracking industry in neighboring Pennsylvania, Gov. Andrew Cuomo on Monday signed a bill banning the importation of hazardous fracking waste into New York.The loophole, they say, had long existed because of the prior definition of hazardous waste that excluded substances like drilling fluids and other material used in exploration and extraction of oil or natural gas.Some of those materials, including rock that environmentalists say contains low-levels of radiation, has been taken to a handful of western New York landfills over the years. Additionally, at least one western New York school used fracking fluid, as a brine, or salty water to help melt ice on its walkways and parking lots. The worry there is that the fluid would run off into the water supply. “New York has led the nation in banning fracking, and we are grateful to Governor Andrew Cuomo for ensuring that fracking waste will no longer contaminate New York’s land and water,” Maureen Cunningham, senior director for clean water at Environmental Advocates NY said of the signing. “Having banned fracking in New York, Cuomo has taken another important step towards making New York frack-free,” added Eric Weltman, of Food and Water Watch. While it has led to an energy boom in places like Pennsylvania, Ohio and Texas, hydrofracking is controversial due to worries about water pollution. Those concerned about climate change also view it as enabling ongoing use of carbon-laden fossil fuels instead of moving toward renewable energy. The environmental group Earthworks in 2019 produced a report showing how waste generated during the fracking exploration process had been placed in landfills in Chemung, Steuben and Allegany counties which are near the Pennsylvania border.
Liberty Utilities Drops Plans For Major Gas Pipeline In N.H. | New Hampshire Public Radio — Liberty Utilities says it will not build the proposed Granite Bridge natural gas pipeline in Southern New Hampshire, after finding a cheaper way to serve new customers by using existing infrastructure. The company told the state of the change in plans in a Public Utilities Commission filing Friday afternoon. The $340-million pipeline plan dated to late 2017 and drew fierce opposition from climate change activists, who oppose any expansion of fossil fuel infrastructure in the region. Natural gas emits less greenhouse gas than coal or oil, but is still a major driver of climate change. Further dependence on gas, through the pipeline plan and still through Liberty’s new alternative, has emerged as a sticking point in the Democratic primary race for governor. Granite Bridge had bipartisan support in the state legislature, including from Senate Democrats who saw a net benefit in extending gas service to residents and businesses who currently rely on expensive, less climate-friendly heating oil. Liberty’s New Hampshire president Sue Fleck called that “critical” in a statement Friday — “not only for New Hampshire’s economy and for families’ pocketbooks, but also to enable the deepest, fastest, and most achievable pathway for decarbonizing our economy and taking action on climate change.” Serving new customers was Liberty’s original goal in building Granite Bridge, which would have run about 27 miles along Route 101 between Stratham and Manchester — branching off the Concord Lateral, an existing, mainline gas artery owned by Texas-based Kinder Morgan. Liberty initially said it would be too expensive to upgrade that larger pipeline to suit their needs. But last fall, PUC staff recommended they revisit that option before Granite Bridge could be approved. “Natural gas, sold responsibly as a rate-regulated commodity, is compatible with bold climate action,” wrote state utility consumer advocate Don Kreis in his column Friday for InDepthNH. “But Granite Bridge was simply too expensive, and too reliant on dreamy estimates of future customer growth, projected too many years into the future.”
Mountain Valley, DEQ reach agreement on environmental fines – The latest problems with muddy runoff streaming from construction sites along the Mountain Valley Pipeline’s route through Southwest Virginia have been resolved, with the company paying $58,000 in fines. The agreement, reached after several months of negotiations with the Department of Environmental Quality, marks the troubled pipeline’s latest penalty for violating erosion and sediment control regulations. Mountain Valley had balked at DEQ’s initial demand for $86,000, which was made after the joint venture of five energy companies building the natural gas pipeline had paid $2.15 million to settle a lawsuit brought by state environmental regulators. The lawsuit filed in 2018 covered violations during the first year and a half of construction; the latest fines were for problems that persisted even after Mountain Valley was ordered to stop work last fall. DEQ initially had cited Mountain Valley for 29 violations from September through March 10, but agreed to drop seven as part of the negotiation process, according to Ann Regn, a spokeswoman for the agency. Negotiations were allowed by a consent decree that settled the 2018 lawsuit, which claimed more than 300 infractions on Mountain Valley’s path through the counties of Giles, Craig, Montgomery, Roanoke, Franklin and Pittsylvania. Also included in the settlement were more intensive, court-ordered environmental inspections, and tougher penalties for additional violations. The fines imposed so far are a paltry sum when compared to the project’s $5.7 billion budget, pipeline opponents have said in calling for tougher enforcement by state and federal officials. “How does MVP continue to rack up DEQ violations when they are supposedly doing repair work under court monitoring and supervision under a court order from a Henrico County judge?” Bonnie Law of Preserve Franklin County said in a statement released by opponents. Critics say erosion from work sites has contaminated nearby streams, which have carried harmful sedimentation as far as the Roanoke River, the source of drinking water for thousands.
Equitrans confirms early 2021 startup for Mountain Valley natural gas pipeline( Reuters) – U.S. pipeline company Equitrans Midstream Corp said on Tuesday it still expects to complete the $5.4 billion Mountain Valley natural gas pipeline from West Virginia to Virginia in early 2021. Mountain Valley is one of several U.S. oil and gas pipelines delayed by regulatory and legal fights with environmental and local groups that found problems with federal permits issued by the Trump administration. Other projects similarly held up include TC Energy Corp’s $8 billion Keystone XL crude pipeline and Energy Transfer LP’s Dakota Access crude pipeline, which are still involved in court battles. Equitrans said in its second-quarter earnings statement that the project’s costs could rise by 5% to around $5.7 billion if it needs “to adapt the construction plan for potential complex judicial decisions and regulatory changes.” When Equitrans started construction in February 2018, it estimated Mountain Valley would cost about $3.5 billion and be completed by the end of 2018. But successful legal challenges to federal permits resulted in lengthy delays and higher costs for Mountain Valley. Equitrans said it expects to receive new approvals soon from the U.S. Fish and Wildlife Service, the U.S. Federal Energy Regulatory Commission and the U.S. Army Corps of Engineers that will enable it to finish building the last 8% of the project. The 303-mile (488-km) pipeline is designed to deliver 2 billion cubic feet per day from the Marcellus and Utica shale in Pennsylvania, Ohio and West Virginia to consumers in the Mid Atlantic and Southeast. Mountain Valley is owned by units of Equitrans, NextEra Energy Inc , Consolidated Edison Inc , AltaGas Ltd and RGC Resources Inc .
22 Virginia legislators urge Gov. Northam and health officials to suspend construction on Mountain Valley Pipeline – Twenty-two Virginia legislators jointly signed a letter urging Gov. Ralph Northam (D-Va) and health officials to halt construction on the Mountain Valley Pipeline during the coronavirus pandemic.This comes after Mountain Valley Pipeline announced it intends to bring more than 4,000 workers to a 30 mile stretch of Southwest Virginia and across the border in West Virginia to work on the pipeline.”An influx of thousands of workers for a project whose completion will not benefit Virginians will needlessly risk accelerating the pandemic in an area of the Commonwealth with already limited health care resources,” said Delegate Chris Hurst, whose district includes the route of the proposed pipeline.Virginia Clinicians for Climate Action observed the counties where the MVP intends to resume work have limited access to Intensive Care Unit beds and a population vulnerable to COVID-19 due to higher concentrations of senior citizens, people in poverty, and people with COPD and cardiovascular disease.This is not the first time MVP has had to put a hold on construction. The full letter can be read below:
Virginia senators again push for pipeline review reforms – Virginia’s Democratic Sens. Mark Warner and Tim Kaine are again proposing reforms to the federal pipeline review process in response to public complaints surrounding the now-cancelled Atlantic Coast Pipeline and the still active Mountain Valley Pipeline through Virginia. Legislation put forward by the senators intends “to strengthen the public’s ability to evaluate the impacts of natural gas pipelines being considered by the Federal Energy Regulatory Commission” and “make it easier for the public to offer input and clarify the circumstances under which eminent domain should and should not be used,” a joint statement from Warner and Kaine said. Several of the suggestions – such as requiring an overall environmental impact evaluation to be done if two pipelines are proposed to be built within a year and 100 miles of each other and mandating that public comment meetings be held in every locality through which a pipeline crosses – also appeared in an earlier version of the legislation that was put forward in 2017 by Warner and Kaine in the Senate and Rep. Morgan Griffith, R-Salem, in the House. That legislation was never voted on. Griffith subsequently introduced another version of the law in January 2019. The legislation put forward Thursday may have a smoother road even in the GOP-controlled Senate, however, given changing attitudes toward natural gas pipelines. A Kaine spokesperson told the Mercury the senators believe “the added provisions in response to recent developments over pipeline litigation will make the bill even more attractive to other members.”Among the new provisions are those preventing pipelines from exercising eminent domain until the project has received all needed permits and FERC has issued rulings on landowner challenges. The latter follows a request in July by Republican FERC Commissioner Neil Chatterjee, who was mulling a run for Virginia governor this spring, and Democratic Commissioner Richard Glick for Congress to pass legislation on FERC rehearing procedures.”We believe that any such legislation should make clear that, while rehearing requests are pending, the commission should be prohibited from issuing a notice to proceed with construction and no entity should be able to begin eminent domain proceedings involving the projects,” the commissioners wrote.
Dominion CEO to Step Down as Utility Marks Massive Loss From Pipeline Cancellation – Dominion Energy is replacing its CEO as part of an executive shakeup accompanying both the Virginia utility’s major shift away from natural gas and toward a renewable energy future, and the hefty financial penalty it incurred for its cancellation of the Atlantic Coast Pipeline project. Dominion announced Friday that CEO Tom Farrell would step down in October and be replaced by Robert Blue, now executive vice president and co-chief operating officer. Farrell will continue to serve as executive chair and chairman of the board of directors, while current co-COO Diane Leopold will serve as the sole COO. The executive shifts were announced on the same day that Dominion reported a second-quarter 2020 GAAP unaudited net loss of $1.2 billion, or $1.41 per share, compared to a gain of $54 million or 5 cents per share for the same quarter in 2019. The loss was largely driven by a $2.8 billion charge related to its cancellation of the Atlantic Coast Pipeline project earlier this month. On a non-GAAP basis excluding those one-time charges, Dominion reported second-quarter operating earnings of $706 million, or 82 cents per share, compared to operating earnings of $619 million, or 77 cents per share, for the same quarter last year. Farrell, who turned 65 in December, said in Friday’s earnings call that Dominion’s new executive shifts are part of a long-running plan to accommodate his retirement. “As executive chair, I will continue to represent the company…[and] will continue to be focused on developing our strategic plan and Dominion’s leadership in the new clean energy economy.” Dominion and partner Duke Energy canceled the Atlantic Coast Pipeline earlier this month, citing costs that have increased from an initial estimate of $5 billion to as much as $8 billion, as well as legal challenges from landowners and environmental groups. On the same day, Dominion announced it was selling its multistate natural-gas pipeline and storage business to Warren Buffett’s Berkshire Hathaway for about $9.7 billion.
Dominion South rally unlikely to fuel Appalachian production growth in 2020 – Rallying forward gas prices at Dominion South are making for a bullish market outlook in Appalachia this winter – a scenario that’s often fueled regional production growth in the past. Following pivotal changes to the industry this year, though, most producers are likely to keep output flat heading into 2021. Stay up to date with the latest commodity content. Sign up for our free daily Commodities Bulletin. Sign Up On Aug. 6, Dominion forward strip prices for first-quarter 2021 settled at an average $2.61/MMBtu, or their highest in three months, S&P Global Platts’ most recently published M2MS data shows. In early May, as US production was nearing its pandemic-fueled bottom near 85 Bcf/d, forwards traders became increasingly bullish on the value of supply from dry basins like the Marcellus and the Utica, lifting winter gas prices at Dominion South in the mid-$2.60s/MMBtu. As the recovery in US gas production stumbles this month, a similar market narrative is gripping the industry. In associated basins like the Permian and the Bakken, the restoration of previously curtailed wells appears to have peaked, leaving US output lurching around 87 Bcf/d. With Appalachia’s wellhead gas prices now headed north of $2, an average unhedged producer in the Marcellus or Utica Shale could be operating above breakeven level by autumn, data compiled by S&P Global Platts Analytics shows. For some producers, it could be enough to tempt fate and resume output growth. According to the chief executive of at least one mid-sized Appalachian producer, though, that outcome is unlikely to play out in 2020, following recent, transformational industry developments this year. After years of overspending and debt leveraging, many Appalachian producers are now finding their back against the wall with the investment community, says Rusty Hutson, CEO of Diversified Gas & Oil. “The equity markets have said enough is enough,” Hutson said. “In the debt markets, it’s extremely hard to refinance – that’s why we’re seeing so much distress and bankruptcy,” Hutson said in a recent telephone interview. On recent second-quarter earnings calls, two of Appalachia’s largest producers, EQT and CNX, said they’re keeping production flat over the near term as they confront a low-commodity-price environment that many analysts expect to endure longer term. Many producers are following suit, but some of the most highly leveraged companies are finding it harder to make the shift to maintenance mode, Hutson says.
U.S. natgas soars nearly 17% as LNG exports rise, heat returns – (Reuters) – U.S. natural gas futures jumped nearly 17% to a near three-month high on Monday as demand rose for exports of liquefied natural gas (LNG), and weather forecasters boosted expectations for hot weather and cooling demand next week. Front-month gas futures rose 30.2 cents, or 16.8%, to settle at $2.101 per million British thermal units, their highest close since May 5. That was their biggest one-day rise since November 2018. “A combination of stagnant production … and a hot change in August’s weather forecasts is creating a bullish set-up that has short sellers running for the exits,” said Daniel Myers, market analyst at Gelber & Associates in Houston, noting this was the front-month’s first close above $2/mmBtu in three months and only the second since late January. Last week, speculators boosted long positions on the New York Mercantile Exchange for a seventh straight week to their highest since November 2018 on expectations energy demand will rise as the economy rebounds from coronavirus lockdowns. Data provider Refinitiv said average U.S. production fell to a two-month low of 87.8 billion cubic feet per day (bcfd) so far in August from 88.0 bcfd in July and an all-time monthly high of 95.4 bcfd in November. With hot weather expected to return, Refinitiv projected U.S. demand, including exports, will rise from an average of 88.8 bcfd this week to 92.5 bcfd next week. U.S. LNG exports in August are on track to rise for the first time in six months as the amount of pipeline gas flowing to the plants rose to 4.0 bcfd so far this month from a 21-month low of 3.3 bcfd in July when buyers canceled dozens of cargoes. That is still well below the record high of 8.7 bcfd in February.
U.S. natgas jumps to highest since Jan on rising LNG exports, hot weather – (Reuters) – U.S. natural gas futures on Tuesday jumped to their highest since January as liquefied natural gas exports rose and on forecasts for hot weather through late August after Hurricane Isaias blows through, keeping air conditioners humming. Front-month gas futures rose 9.2 cents, or 4.4%, to settle at $2.193 per million British thermal units, their highest close since Jan. 10. That put the contract into overbought territory with a Relative Strength Index (RSI) over 70 for a second day in a row for the first time since November 2019. On Monday, volume in the front-month, which soared almost 17%, topped 381,000 contracts, its highest since hitting a record 495,196 in November 2018 during the market’s most volatile period, when it rose 18% one day and fell 17% the next. Hurricane Isaias, which hit North Carolina overnight, broke the heat wave that has blanketed much of the country since late June. The storm left more than 1.4 million homes and businesses from New York to North Carolina without power on Tuesday and was expected to cause more damage as it scrapes north up the East Coast. But with hot weather expected to return after Isaias blows away, data provider Refinitiv projected U.S. demand, including exports, will rise from an average of 88.6 bcfd this week to 91.8 bcfd next week. That, however, is a little lower than Refinitiv’s outlook on Monday as higher prices cause power generators to burn more coal instead of gas. U.S. LNG exports are on track to rise for the first time in six months as the amount of pipeline gas flowing to the plants rose to 4.0 bcfd in August from a 21-month low of 3.3 bcfd in July when buyers canceled dozens of cargoes.
US working natural gas volumes in underground storage rise by 33 Bcf: EIA | S&P Global Platts – Natural gas volumes in US underground storage facilities increased in line with the five-year average while the Henry Hub prompt month contract continues to push above prices not seen since early January as the final three months of injection season commence. US underground natural gas storage inventories increased by 33 Bcf to 3.274 Tcf in the week that ended July 31, according to US Energy Information Administration data released Aug. 6. The injection was larger than the consensus expectations of analysts surveyed by S&P Global Platts, which called for a 27 Bcf build. Responses to the survey ranged from an injection of 20 Bcf to one of 33 Bcf. The injection measured less than the 58 Bcf build reported during the same week last year, but matched the five-year average build of 33 Bcf, according to EIA data. Storage volumes now stand 601 Bcf, or 22.5%, above the year-ago level of 2.673 Tcf and 429 Bcf, or 15%, higher than the five-year average of 2.845 Tcf. The NYMEX Henry Hub September contract added 3 cents to $2.22/MMBtu in trading following the release of the weekly storage report at 10:30 am ET. NYMEX Henry Hub prices over the last week have staged an impressive rally as the balance-of-summer strip, now comprising just September and October, has increased by more than 25 cents on diminishing expectations that storage will breach the 4 Tcf mark by the end of season. The winter strip, likewise, has moved higher as well, settling at $2.95 in at Aug. 5 close and gaining another 2 cents in the session Aug. 6. LNG feedgas has broken above 4 Bcf/d in August, according to S&P Global Platts Analytics. It marks the first time LNG feedgas demand climbed above 4 Bcf/d since June 30, an increase of over 800 MMcf/d from the prior week’s average. Although total US liquefaction utilization remains under 40%, there are expectations for stronger feedgas demand in September and October, when US Gulf Coast netbacks are in positive territory. US production has averaged 87 Bcf/d to start August, 300 MMcf/d lower than July. Roughly half of the production losses are maintenance driven, and expected to return by Aug. 7, but the overall risks to the remainder of the summer skew bullish due to strong power burn demand and the recovery in LNG feedgas demand. Despite lower week-over-week production and higher LNG demand, models point to a larger injection for the week in progress. For example, Platts Analytics’ supply and demand model currently forecasts a 52 Bcf injection for the week ending Aug. 7. This would increase the surplus to the five-year average by 8 Bcf. Recent changes to supply and demand fundamentals have lowered Platts Analytics’ forecast for end-of-season inventories from 4 Tcf down to 3.858 Tcf, which would only register about 50 Bcf more than the five-year average before withdrawal season begins in early November.
Natural Gas Futures Slip as EIA Storage Data Reflects ‘Woefully Oversupplied’ Market – Natural gas futures buckled under pressure Thursday after a slightly larger-than-expected storage injection sapped the momentum prices had earlier in the week. The September Nymex futures contract settled at $2.165, down 2.6 cents day/day. October also slipped 2.6 cents to $2.305. Spot gas prices softened across the board as well, dragging down NGI‘s Spot Gas National Avg. 8.0 cents to $1.830.After a stunning rally to start the week, Nymex futures had been expected to retreat a bit, especially with cooler weather in the forecast. While Wednesday’s price action failed to move the needle, bears got the upper hand on Thursday after the latest government data pointed to a market that remains “woefully oversupplied,” according to NatGasWeather.The Energy Information Administration (EIA) reported that inventories for the week ending July 31 rose by 33 Bcf, which came in far below last year’s 58 Bcf injection but was exactly on par with the five-year average. This is important to consider, NatGasWeather said, because “cooling degree days were solidly hotter/greater than normal, which is indicative of a market still solidly oversupplied.”Broken down by region, the Midwest led with a 15 Bcf injection into stocks, while the East came in with the second-highest build of 12 Bcf, according to EIA. Mountain inventories rose by 6 Bcf, and the Pacific withdrew 2 Bcf. The South Central reported a net injection of 3 Bcf, but salt facilities fell by 3 Bcf while nonsalts added 6 Bcf. Total working gas in storage as of July 31 stood at 3,274 Bcf, 601 Bcf higher than last year and 429 Bcf above the five-year average, EIA said. Price action following the EIA report was swift. In the minutes leading up to the report, the September Nymex contract was trading at $2.245, up 5.4 cents from Wednesday’s close. Earlier, it had soared as high as $2.284. As the print crossed trading desks, the prompt month slipped to $2.225, but then it bounced around as traders attempted to digest the data. Looking ahead to next week’s EIA report, analysts expect a heftier build of about 50 Bcf as temperatures have cooled and East Coast power demand has been crushed by former Hurricane Isaias. This would put the end-of-season figure at or above the top of the seasonally adjusted range, Schork noted. “That is not a bullish thing.”
U.S. natgas soars to December high in best week since 2009 – (Reuters) – U.S. natural gas futures on Friday jumped to their highest since December after rising by the most in a week since 2009, as liquefied natural gas (LNG) exports increased and forecasts called for hot weather through late August. “The LNG market’s worst days appear to be behind it, with fewer cancellations in September expected to bring utilization back toward 60% before an even stronger recovery in October,” said Daniel Myers, market analyst at Gelber & Associates in Houston. Front-month gas futures rose 7.3 cents, or 3.4%, to settle at $2.238 per million British thermal units, their highest close since Dec. 26. For the week, the contract was up 24%, its biggest weekly gain since September 2009. Although U.S. and European gas contracts mostly trade on their own fundamentals, gas at the European Title Transfer Facility benchmark in the Netherlands also soared this week, jumping 50%. That made it profitable for more U.S. LNG cargoes to go to Europe again for the first time in months. U.S. LNG exports in August were on track to rise for the first time in six months as the amount of pipeline gas flowing to the plants climbed to 4.0 billion cubic feet per day in August from a 21-month low of 3.3 bcfd in July, when buyers canceled dozens of cargoes – the most in a month. With hot weather expected to return after Hurricane Isaias cooled the East Coast, data provider Refinitiv projected U.S. demand, including exports, will rise from an average of 88.5 bcfd this week to 90.6 bcfd next week and 91.9 bcfd in two weeks. That is a little lower than Refinitiv’s outlook on Thursday as higher gas prices cause power generators to burn more coal instead of gas.
IEEFA report: China unlikely to come to rescue of overbuilt U.S. LNG industry – A rebound of the ailing U.S. liquefied natural gas (LNG) industry isn’t likely to come from Chinese demand, according to a new study by the Institute for Energy Economics and Financial Analysis (IEEFA). Global LNG markets have been hammered by collapsing prices, falling consumption, and an enormous supply glut in Europe and Asia, even as the U.S. LNG industry continues with expansion plans. “The U.S. liquefied natural gas industry is suffering through a worse-than-worst case scenario: An international market collapse on a scale that seemed inconceivable when the country’s first export facility was put into service just over four years ago,” said Clark Williams-Derry, an energy finance analyst and co-author of No Upside: The U.S. LNG Buildout Faces Price Resistance from China. Accentuating the industry’s troubles, Cheniere Energy, the largest U.S. LNG company, is likely to collect most of its revenues this summer from shipment cancellation fees, rather than actual LNG sales. Although LNG has become the worst-performing global energy commodity during the coronavirus pandemic – worse even than coal or oil – its problems predate the economic downturn. More than 20 U.S. projects in various stages of development, as well as 20 existing commercial-scale plants, are competing with new LNG plants in Russia, Australia, Malaysia and Cameroon. The ensuing glut has convinced many international buyers to obtain LNG from spot markets rather than signing new long-term contracts. Prior to 2019, China had been the world’s fastest-growing LNG consumer, leading to hopes that it could rescue the planned U.S. LNG buildout. The IEEFA analysis, however, finds that PetroChina, China’s largest natural gas company, has lost money on gas imports every year since 2015, throwing doubt on the Chinese gas market’s ability to absorb new imports.If China is to expand its LNG imports, it will likely have to secure long-term supplies at prices well under $7/MMBtu, Williams-Derry said. Even with U.S. costs close to historically low levels, the margin for reaching those prices is slim: Shipping LNG from the Gulf of Mexico to East Asia costs about $2/MMBtu for feedstocks, $3/MMBtu for liquefaction, and $1/MMBtu for transportation. Regasification and transportation to Chinese cities would add another $1/MMBtu to the total cost. The IEEFA study examined gas pricing in seven major Chinese cities with access both to LNG terminals and pipeline gas. Wholesale prices in April 2019 ranged from $7.73/MMBtu to $8.57/MMBtu; at the time, it cost roughly $8/MMBtu to deliver gas from the Gulf of Mexico to China, meaning that U.S. LNG offered little or no economic benefits to Chinese consumers. ‘
China only fulfils 5% of Sino-U.S. energy trade deal in first half of 2020 – (Reuters) – China bought only 5% of the targeted $25.3 billion in energy products from the United States in the first half of 2020, falling well short of its trade deal commitments at a time when relations between the two top economies are already sour. China’s imports of crude oil, liquefied natural gas (LNG), metallurgical coal and other energy products totalled around $1.29 billion this year through June, according to Reuters calculations based on China customs data. While Chinese purchases of U.S. products accelerated recently, analysts say weak energy prices and worsening relations means Beijing may undershoot its full-year goal in the Phase 1 deal agreed in January. (GRAPHIC – China only achieved 5% of the $25.3 bln energy target in the first half of 2020: here) (GRAPHIC – China’s energy imports from U.S.: here) “China is unlikely to fulfil its Phase 1 commitments as they were overly ambitious to begin with,” said Michal Meidan, a director at the Oxford Institute for Energy Studies, adding she expected Beijing to step up purchases to show goodwill. Failure to meet the target could further strain U.S.-China relations, which have nosedived since the outbreak of the coronavirus. (GRAPHIC – Apparent consumption of refined oil products in China: here) (GRAPHIC – Apparent consumption of natural gas in China: here) U.S. crude oil had been expected to feature prominently in China’s Phase 1 purchases. But a surge in freight rates coupled with a collapse in fuel demand, as the coronavirus spread, made U.S. imports relatively costly for refiners in China. China imported only 45,603 barrels per day (bpd) of U.S. oil in the first half of 2020 compared with 85,453 bpd in the same period in 2019.Sushant Gupta, research director at consultancy firm Wood Mackenzie, said that to meet the trade deal target, China would need to import 1.5 million bpd of U.S. crude in 2020 and 2021, revising that estimate up from nearly 1 million bpd previously as low oil prices reduced the value of crude purchases.(GRAPHIC – China’s crude oil imports: here)China’s refiners boosted U.S. purchases after flagship oil grades slumped into negative territory in April. (GRAPHIC – Crude oil and LNG prices: here)
Northern Natural pitches Northern Lights 2021 to serve winter peak-day needs | S&P Global Platts – Berkshire Hathaway Energy’s Northern Natural Gas has proposed a scaled-down version of its Northern Lights 2021 natural gas pipeline expansion, meant to keep up with needs of several existing customers and providing 45,693 Dt/d of incremental winter peak-day service.The proposal is a continuation of the pipeline company’s broader Northern Lights project, which it describes as a multi-year commitment to expand its market-area capacity in response to customers’ growth requirements through 2026.In the application posted on the Federal Energy Regulatory Commission’s website Aug. 1, Northern Natural said contract extensions and growth commitments under the Northern Light expansions were critical in preventing a major bypass of Northern’s system by some customers. In the absence of the extension agreements with customers CenterPoint Energy Resources, Xcel, and Flint Hills Resources, a bypass would have translated to a loss of about 1 Bcf/d of their existing winter maximum daily quantity, Northern Natural told FERC.The proposed Northern Lights 2021 Expansion (CP20-503) entails an 11,153 hp greenfield compressor station in Pine County, Minnesota, additional compression at the Pierz compressor station in Morrison County, modifications to the Pierz interconnect, and a pipeline loop and extension totaling 1.43 miles as well as replacement of 0.08 of an 8-inch-diameter pipeline with 12-inch-diameter pipeline and changes, all in Minnesota.The proposal is scaled back from the November 2019 plan put forward during a prefiling review at FERC that pitched more than eight miles of 30-inch-diameter and 36-inch-diameter mainline loops and extensions, and over 13 miles of branch line loops and extensions.
Range to Sell Louisiana Acreage, Cut 100 Jobs — Range Resources Corp. is selling its Louisiana shale fields for about one-10th of what it paid for them just four years ago as depressed natural gas prices hammered the heavily indebted driller. Range agreed to sell the assets acquired in its 2016 takeover of Memorial Resource Development Corp. to Castleton Resources LLC for $245 million, according to statements by both companies Monday. Range stands to reap an additional $90 million in the future, contingent on higher commodity prices. The $335 million potential total value compares to the approximately $3.3 billion Range originally paid in an all-stock deal for the fields. The biggest-ever deal for Range turned into a bust when the company’s geologists and engineers soured on the quality of the rocks in early 2018. Range is also cutting 100 jobs, or about 17% of its workforce, mostly as a result of the sale, Chief Financial Officer Mark Scucchi said during a conference call with analysts on Tuesday. The sale is expected to close this month and the effective date will be backdated to Feb. 1, according to the statement. Castleton Resources is owned by Castleton Commodities International LLC and Tokyo Gas Co.
Permian Execs Signal Milestone— America’s most prolific shale drillers are accepting a fate once anathema to an industry obsessed with growth: drilling just to ward off production drops. The pandemic and subsequent plunge in crude prices has forced U.S. crude explorers to scrap plans to expand supplies amid investor skepticism toward the shale business model. For some of the biggest names in the Permian, that’s meant vowing restraint as long as oil lingers at levels too poor to justify a new boom. “Certainly we’re not seeing any signals that growth is needed,” Travis Stice, chief executive officer Diamondback Energy Inc., said during a conference call on Tuesday. “Growth in today’s world is pretty much off the table.” Management teams chastened by crude’s precipitous fall below zero earlier this year are beginning to outline 2021 spending plans. Diamondback said it’ll maintain oil output at this year’s level, which is expected to be dramatically lower than 2019. Concho Resources Inc. expressed similar intent last week. Centennial Resource Development Inc. declined on Tuesday to provide 2021 production guidance. In the fourth quarter, the explorer plans to employ just a single rig, a signal of little growth going into next year. Drillers are focusing shrunken capital budgets on minimizing the steep output declines unique to shale wells, which start out as gushers before quickly declining to trickles. In a handful of cases, spending has been cut so dramatically that executives expect to generate positive cash flow despite enduring the most tumultuous year since the start of the U.S. shale boom. “For most of my career, we would reinvest all our cash flow and then show our success by how much we could grow our production,” Concho CEO Tim Leach said last week. “Well, that’s not how it’s going to work in the future.” A moderation in growth had been anticipated as years of heavy borrowing took a toll on balance sheets and investors blanched at weak or non-existent returns. Supermajors Exxon Mobil Corp. and Chevron Corp. were expected to pick up the slack via ambitious growth plans to pump 1 million Permian barrels a day each by the middle of the decade. But the pandemic threw all prognostications into disarray. Chevron is forecasting a 7% decline in its Permian production next year. Although Exxon didn’t provide a production outlook when it disclosed quarter results last week, the company indicated that its daily Permian output wouldn’t increase much beyond the current 345,000 barrels.
Oil companies are backing Trump’s re-election after giving heavily to Clinton in 2016 –American industries tend to play both sides by donating to candidates from both major political parties. That’s particularly true when it comes to the presidency, which oversees a vast federal bureaucracy influencing trillions of dollars in spending. Even the oil and gas industry, which strongly favors Republicans, split its ticket when it came to the White House race in 2016. The industry gave $1.2 million to Donald Trump, whose campaign won over swing states such as Pennsylvania by chanting “drill, baby, drill.” But it also bequeathed $1 million to Democrat Hillary Clinton, who had promised to put “coal companies out of business” (while helping displaced workers find new jobs).Not this year. Trump is reaping the rewards of being the most pro-fossil fuel president in modern history. The industry has donated $936,000 to his 2020 reelection campaign, according to the Center for Responsive Politics. That’s roughly triple the haul of his presumptive Democratic challenger Joe Biden, who has collected only $265,000 in industry donations as of August. The biggest donors to all political candidates among oil and gas companies were a mix of traditional activists such as Koch Industries ($9.8 million), oil majors such as Chevron ($4.7 million), and shale oil firms like Midland Energy ($2 million). The vast majority of the $6.7 million given by top donors has gone to Republicans in Congress this election cycle. Only two Democrats – Senator Bernie Sanders (Vermont) and Rep. Lizzie Fletcher (Texas) – were even among the top 20 recipients. The reason seems clear. Biden has embraced the climate movement and his party’s enthusiasm for a clean energy transition. Under Biden’s $2 trillion climate plan announced this July, the US will achieve zero net-emissions by 2050, eliminate electric grid emissions by 2035, promote renewable wind and solar energy development, and recommit to the Paris climate accords. Biden also agreed (along with every major Democratic presidential nominee) to end the extraction of fossil fuels on public lands. That’s significantly more ambitious than Clinton’s proposal in 2016.
Trump: Radical Left Wants To Leave Every City At Their Mercy, Incite Riots – President Donald Trump lashed out at radical Democrats, calling them “sick” and accusing them of not loving the country in a speech he delivered Wednesday on restoring American energy dominance and the U.S. economy. “The radical left wants to tear down everything in its way,” Trump said. “And in its place, they want power for themselves. They want power. Hard to believe – power. They want to uproot and demolish every American value. They want to wipe away every trace of religion from national life. They want to indoctrinate our children, defund our police, abolish the suburbs, incite riots, and leave every city at the mercy of the radical left. That’s not going to happen. That’s not going to happen.” “Their platform calls for mandating zero-carbon emissions from power plants by 2035. In other words, no drilling, no fracking, no coal, no shale, no gas, no oil; otherwise, they’ve been very good to the industry, I think.You got to be careful. You know, people don’t take it seriously. If they got in, you will have no more energy coming out of the great state of Texas, out of New Mexico, out of anywhere – Oklahoma, North Dakota. Name them. Pennsylvania. Pennsylvania does a lot. People don’t realize that. A lot. It would throw Pennsylvania, Ohio – so many other places. You don’t realize how big it is. They want to have no fracking, no nothing. The policies required to implement this extreme agenda would mean the death of American prosperity and the end of the American middle class. It would mean, I think, even worse than that. It would destroy our country. I used to say, “Would become another Venezuela.” Same ideology. You would become another Venezuela. Venezuela used to be one of the richest in the world, per capita, and period, one of the richest in the world – among the largest oil reserves. Now they don’t have water, they don’t have medicine, they don’t have food. You got a lot of oil; it doesn’t matter. Doesn’t seem to matter. They don’t have anything. And that can happen to us.”
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